5pm – 6.30pm
Welcome reception in the Exhibition Hall
by Brett Wakeham and Jeff Fleming, TransCanada PipeLines, Calgary, AB, Canada
This paper reports on a pre-ILI cleaning operation in a 30” sweet, dry natural gas pipeline in Alberta. Data collected from an initial ILI tool run was degraded and, for some portions of the pipeline, unusable, leading to the decision to organize a cleaning program.
The line was previously inspected with a MFL tool in 2005 and was scheduled for re-inspection in 2010 based on corrosion growth analysis. The MFL re-inspection was scheduled for January, 2010 following a cleaning tool run and a gauge tool run. Due to large volumes of debris that were received with the cleaning tool, the decision was made to expand the effort with additional cleaning tool runs. The MFL inspection proceeded after 5 cleaning runs and in their data quality assessment, the inspection vendor reported sensor lift-off which impacted approximately 13% of the data. The sensor lift-off occurred in the pipe bottom and it continued for approximately 35 km shortly after launch. Both the pipeline operator and vendor deemed this to be a failed inspection and determined that an aggressive cleaning program would be required prior to re-running the MFL tool.
Experience on the pipeline segment that supplies gas to this line suggested that cleaning pigs would not be an effective solution. Despite running ten cleaning tools in the upstream segment, three subsequent MFL inspection attempts encountered sensor lift-off, and the cleaning tools only moved the debris a very short distance. Ultimately, a gel chemical in conjunction with batching pigs was selected.
The proposed cleaning included two liquid slugs - a 190,000L slug of hydrocarbon-based gel and distillate which would be followed by a 37,000L slug of breaker in order to return residual gel to a liquid state for easier removal from the pipeline.
Chemical cleaning on a large-diameter natural gas transmission line is complicated by a variety of operational and logistical issues. A number of producer sites were shut in for the duration of the project, and gas flow on the line was reversed in order to achieve the required flow conditions (3 m/s gas velocity). Other logistical concerns included having a launch site that is directly upstream of a large compressor station, limited road access for tracking the tools and the equipment set up for recovering the large liquid volumes at the receive site.
Upon completion of the chemical cleaning program a final MFL ILI tool was run through the pipeline segment. The ILI vendor confirmed within 24 hours of receiving the MFL tool that no sensor lift-off had occurred during the run; complete data coverage of the line was attained.
This case study will focus on:
by Keith Allan, Clariant, Houston, TX, USA
This presentation will discuss development of a cleaning chemical for hydrocarbon transport pipelines. Details of the formulation research and laboratory testing are summarized, along with case histories of applications in western USA and the US Gulf Coast.
Hydrocarbon transportation can result in precipitation of paraffins, asphaltenes, and naphthenates which adsorb to the walls of the pipeline becoming associated with iron sulfides forming from corrosion. Pigging operations alone do not always remove all these deposits due to compaction and a strong adherence to the walls of the pipeline. It therefore becomes necessary to add surfactant based chemicals to assist in the break-up and removal of these deposits.
One case history details how the pipeline operator had previously tried to clean a 12” 9-mile section of pipeline with a pig. The pig was launched and became stuck along the length of the pipeline. Application of the newly developed product freed the stuck pig and removed the significant debris that the pig had become lodged against.
by Geoff Wilkinson, Pipeline Engineering, Catterick Bridge, UK
This paper will provide an overview of a patented Automatic Multiple Pig Launching system that has been developed to individually launch pigs from a preloaded cassette. The system requires no modification to an existing pipeline launcher, as the pig launching is controlled by a hydraulic system incorporated within the pigs rather than the launcher itself.
Frequently pigged lines are one of the areas where automated multiple pig launching technology can offer significant benefits, with other applications including unmanned offshore platforms, isolated launch sites and subsea pigging operations.
The system development has taken three years to design and fully test, involving a full scale trial at a 1-km test loop. The development and testing was supported by a consortium of oil and gas companies. This paper will discuss the development steps and the fundamentals behind the system design.
The paper will also present a case study from a recent 10” six-pig automated multiple pig launching system used in a 27-mile long, wet gas gathering system which is pigged on a daily basis. To support the independent launching of the pigs, the client fully automated the launching and receiving sites, now controlled by a SCADA system and operated remotely, thus reducing personnel time on site and the number of trap interventions.
by Andrew Pulsifer, CenterPoint Energy, Houston, TX, USA
The ideal pig speed for most effective cleaning of gas transmission pipelines has been tagged (unofficially) at between 5 and 7 mph. At higher pig speeds, pigs are likely to jump over girth welds, consequently increasing the risk of leaving behind debris/liquid fields at these locations. This can lead to internal corrosion and jeopardize the pipeline integrity. Maintaining optimal speed of the cleaning pig is a difficult challenge in high flow conditions. Reducing gas flow rates to lower pig speeds is an undesirable option as this not only impacts gas reliability for the downstream client base but also has a significant negative influence on transportation revenue.
Recent application of a Speed-Controlled Pig (SCP) using a combination of fixed and variable bypass has allowed mechanical pipeline cleaning to continue without reducing gas volume or negatively impacting transportation revenues. This presentation is an operator’s perspective on running an SCP in large-diameter high-volume pipelines, including a discussion of obstacles and successes encountered, as well as how continued improvements to the SCP are expected to allow the company to effectively clean these pipelines, without compromising gas delivery or production.
by Dr John Smart, John Smart & Assocs, Houston, TX, USA, and Robert H. Winters, Champion Technologies, Lafayette, LA, USA
Black powder, a mixed corrosion product found in pipelines, can accumulate in the line but will move when the velocity reaches a critical value of about 12-14 fps in dry gas pipelines. This velocity increases to about 30-40 fps when the pipeline contains compressor oil, glycol, or corrosion inhibitors, which cause the powder to stick to the sides of the pipeline. Once in motion, black powder can travel great distances. Large quantities of black powder have been found in some pipelines, which can seriously damage compressors, valves, instrumentation, and customer’s equipment. It also increases pressure drop in the line, which can significantly increase fuel costs for compressors. The nature of black powder is discussed, and field experiences are presented to illustrate problems found. Cleaning black powder from pipelines can be difficult, and recontamination of pipelines can occur rapidly. Options to protect the integrity of the pipeline are discussed.by Leo Aldeen, INTECSEA, Houston, TX, USA, Dave Agerton, Consultant, Houston, TX, USA, and Leith McDonald (provisional), BP, Houston, TX, USA
Multi-diameter pipeline systems have become increasingly attractive because marginal fields, when tied into a main export pipeline, are more commercially viable. The need for multi-diameter pigs has therefore been rising for more than two decades. However, advances have been slow because of the challenges involved. This is especially the case when the change in diameter (the ratio of maximum to minimum diameter), increases far beyond that of wall thickness variation. A higher threshold of difficulty is set when this ratio exceeds 30%. The increased flexibility needed for negotiating the changing diameters and the pipeline’s geometries makes multi-diameter pigs inherently less efficient than conventional pigs.
There is a significant difference between pigging with liquid and pigging with gas, but this is often overlooked during pig selection. Pigging liquid lines is less demanding than pigging gas lines except when displacing large amounts of debris and scraping for wax. High sealing pigs for the dewatering of gas lines are even more difficult to achieve.
The simplest approach for a multi-diameter system is to design the pig to perform its particular function in the smaller diameters only and allow it to be entrained in the flow through the remainder of the system. As the diameter change increases, it becomes almost impossible for a pig to function effectively throughout the entire system. Nevertheless, every pig must perform its intended, duty, otherwise the risk of pigging is taken for no benefit.
To have pigs available for multi-diameter systems, it is imperative that they are developed and methodically tested to ensure they can traverse the entire system without the risk of a blockage. This in turn means that, although costly, there is a need for appropriate testing facilities. The consequences of a subsea blockage far exceed the cost of pig testing.
This paper describes the various challenges that had to be overcome during the pigging trials performed at BP’s Hufsmith site during the development and empirical testing of the multi-diameter pigs required for the Enbridge Neptune oil and gas pipelines. The efforts to extend the pigging capability from a 30% to a 70% diameter change are also discussed, together with pig material, flexibility, operational considerations and flow limitations.
by Keith Swinden, SIG Ltd/Genesis Oil & Gas Consultants, Aberdeen, UK
Many pipelines cannot be internally inspected for various reasons; they may have reductions or changes in ID, extreme angles or 90-degree mitre bends, T-junctions, Y-junctions or simply an access point for pigs without a recovery point. They may be empty, gas filled, have no flow or flow in the “wrong” direction. Individually or collectively, these conditions render large sections of pipeline unpiggable.
To address the problem of ‘uniggable’ pipelines, SIG has developed a range of high-powered tethered brush tractor crawlers that function as delivery systems for a variety of applications including internal pipeline inspection, cleaning and, later, repair. The first 16” and 10” units began operating in 2010, and there is demand for units as small as 4-6” and as large as 42” and beyond.
The brush-drive system copes well with internal pipeline irregularities caused by corrosion, mechanical damage and sedimentation as well as changes in pipe ID. Articulated propulsion and sensor-carrying modules allow the vehicle to negotiate 90° bends. As the crawlers have truly bi-directional capability, they reverse back to the point of entry, needing only a single point for both insertion and recovery.
The crawlers are designed as internal pipeline cleaning and delivery systems with extremely high-traction (5-20-metric-ton pull depending on size and configuration) and a long-range capability (4-8 miles, depending on pipeline geometry). They operate independently of pipeline flow; with the flow (at the vehicle’s own speed), against it and also with no flow at all in empty pipelines.
High-traction power allows them to work in vertical pipelines, allowing examination of risers, and to remain stationary for extended periods in any attitude to monitor regions of high stress, such as pipeline touchdown points, over time.
Integrated operational payloads carried are designed to best address clients’ requirements; multiple sensor packages can include MFL, UT, electromagnetic acoustic transducers (EMAT) or other pulsed EM and acoustic systems plus optical/laser systems and so reduce operational time and cost by performing several tests in one single pass.
by Bernd Selig, Process Performance Improvement Consultants, Bloomfield, CT, USA
ABSTRACT TO COME
by Alexander Guzman et al., Ecopetrol, Bogota, Colombia
This paper describes Ecopetrol’s integrity management model for approximately 7,000 km of pipelines in Colombia. The model is part of a comprehensive process aimed at maintaining Operational Reliability. The plan is driven by Risk-Based Inspection (RBI) and is managed by an oversight group of specialists in materials engineering, corrosion control, risk assessment, planning, civil engineering and geotechnical engineering.by Jens Thygesen, Horsholm, Denmark
The presentation will describe an Automatic Identification System (AIS) which may provide a significant improvement in offshore pipeline operators’ emergency response to mechanical damage incidents. The continuous monitoring of vessel traffic above the subsea pipelines will add great value to the integrity management database and input for risk-based inspection planning. It should also become a valuable supplement for the pipeline operator to mitigate damage to the network, thereby minimizing risk to personnel and the marine environment.
By Louis Pretorius, CorroCoat SA, South Africa
Pigging of long pipelines is a technique for in situ (field) coating, creating seamless internal structural linings. Originally developed for cleaning pipes, the system was adapted to apply internal anti-corrosion protection to pipes using a thin epoxy layer, which had some problems in weld coverage, stress cracking, poor cold weather curing and the inability to fill pitting corrosion metal loss.
New coating materials, revised application methods and modified pigging equipment have made it possible to apply field applied coatings up to 1 mm thick, as an internal corrosion barrier to pipes, in a single application (similar to continuous screeding) resulting in a bonded “GRP pipe within the pipe”. The method can be used for new projects on fully welded pipelines avoiding coating problems associated with flange joints couplings or weld lets, or for refurbishment of old pipelines. Pipes varying from 150-900mm diameter, up to 12 km long can be treated. The pipelines can be buried, submerged, continuously welded or flanged. Many different pipes, such as oil platform-to-shore pipelines, injection lines, cooling water lines etc., can all be treated using this method. Thick-film polymer pigging techniques create new possibilities for engineers to stop corrosion damage, refurbish and extend the life of pipeline systems, all with significant cost savings compared to replacement pipe.by Jim Marr, TransCanada PipeLines, Calgary, AB, USA
TransCanada typically manages the integrity of sections of gas transmission pipelines susceptible to stress corrosion cracking (SCC) by periodically performing hydrostatic testing. Interest in an alternative approach to manage SCC and other forms of longitudinally-oriented defects led to endorsement of the latest generation of dry-coupled ILI tools. GE´s EMAT tool uses the electromagnetic acoustic transducer technology to meet this requirement. This paper will summarize field experience results of the latest generation EMAT ILI tool, which has been commercially available since September 2008. It demonstrates that the challenges have been overcome, the targets have been achieved, and the tool now delivers superior detection, sizing and discrimination performance, all key parameters to conduct an effective pipeline integrity program.
by Taylor M Shie, and Dr Thomas A Bubenik, DNV Columbus, Dublin, OH, USA, and Daniel J Revelle, Quest Integrity Group, LLC Boulder, CO, USA
DNV Columbus was retained by a pipeline operator to provide independent verification of the performance specifications of Quest Integrity Group’s InVistaTM tool. The tool is a straight-beam ultrasonic tool capable of detecting and sizing dents, metal loss, and dents with metal loss. This multiple phase project evaluated the performance of the inspection tool against its stated capabilities. The InVistaTM tool is an emerging technology and was designed to navigate tight bends (up to 1D) and back to back bends.
by Jeff Harris, Rosen USA, Houston, TX, USA, and Paul
Guy, Superior Pipeline Services, Indiana, PA, USA
As pipeline operators work to complete their baseline assessments many have found it difficult to find economical ways to thoroughly inspect their challenging pipelines, or “nuisance” HCA’s. Pipeline segments with small inspection length, cased road crossings, river crossings, and systems with no or low product flow, are examples of pipelines that have been deemed unpiggable according to traditional in-line inspection methods. By joining together with Superior Well Services, Rosen USA found a partnership that brought together experience not previously seen in the industry in regards to ILI technologies and tethered, or wire line, inspections. Rosen USA together with Superior Well Services, is able to leverage Superior’s wireline, or downhole, equipment and expertise and apply it to the inspection of oil and gas pipelines. The downhole wire line inspection technique has been used in the oil field for decades, but tethered inspection is less prevalent in traditional oil and gas pipeline systems. This paper discusses the capabilities of tethered in-line inspection. The discussion will include benefits of using ILI for unpiggable pipeline segments vs. ECDA or hydrotesting, give operators an understanding of project management needs and set expectations, what types of ILI technologies can be used, and the quality of data that operators can expect to obtain from tethered inspections.
by Neil Bates, David Lee, and Cliff Maier, DNV Canada, Calgary, AB, Canada
This paper describes case studies involving crack detection ILI and fitness-for-service assessments that were performed based on the inspection data. The assessments were used to evaluate the immediate integrity of the pipeline based on the reported features, and the long-term integrity of the pipeline based on excavation data and probabilistic SCC and fatigue crack growth simulations. Two different case studies are analyzed, which illustrate how the data from an ultrasonic crack tool inspection was used to assess threats such as low-frequency electrical resistance weld seam defects and stress corrosion cracking. Specific issues, such as probability of detection/identification and the length/depth accuracy of the tool, were evaluated to determine the suitability of the tool to accurately classify and size different types of defects. The long-term assessment is based on the Monte Carlo method, where the material properties, pipeline details, crack growth parameters, and feature dimensions are randomly selected from certain specified probability distributions to determine the probability of failure versus time for the pipeline segment. The distributions of unreported crack-related features from the excavation program are used to distribute unreported features along the pipeline. Simulated crack growth by fatigue, SCC, or a combination of the two is performed until failure by either leak or rupture is predicted. The probability-of-failure calculation is performed through a number of crack-growth simulations for each of the reported and unreported features and tallying their respective remaining lives. The results of the probabilistic analysis were used to determine the most effective and economical means of remediation by identifying areas or crack mechanisms that contribute most to the probability of failure.
by Reena Sahney and Guy Desjardins, Desjardins Consulting, Calgary, AB, Canada and
Shahani Kariyawasam and Hong Wang, TransCanada Pipelines, Calgary, AB, Canada
As part of ongoing continuous-improvement efforts, TransCanada is in the process of analyzing system-wide historical failure data to understand trends and benchmark risk algorithms. Failure assessment of in-service and hydrotest failures is a good diagnostic tool of threats to the pipeline system. This knowledge and understanding can be used in building risk algorithms. Quantification of failure rates also allows the risk values among different threats and along the pipeline to be benchmarked appropriately. Therefore, as a preliminary step towards improving risk algorithms TransCanada has analyzed the failure data. This analysis is performed in three steps and then validated.
by Jane Dawson, Paul Senf, and Jeff Sutherland, PII Pipeline Solutions, Houston, TX, USA
This paper describes the processes used to analyze repeat ultrasonic crack detection ILI data and the information on crack growth that can be obtained. Discussions on how technical improvements made to crack sizing accuracy and how field verification information can benefit integrity plans are also included.
ILI ultrasonic crack detection has good correlation with the crack layout on the pipe and estimating the maximum crack depth for the crack or colony. Recent analytical developments have improved the ability to locate individual cracks within a colony and to define the crack depth profile.
As with the management of corroding pipelines, the ability to accurately discriminate active from non-active cracks and to determine the rate of crack growth is an essential input into a number of key integrity management decisions. For example, in order to identify the need for and timing of field investigations and/or repairs and to optimize re-inspection intervals crack growth rates are a key input. With increasing numbers of cracks and crack colonies being found in pipelines there is a real need for reliable crack growth information to use in prioritizing remediation activities and planning re-inspection intervals. So as more and more pipelines containing cracks are now being inspected for a second time (or even third time in some cases), the industry is starting to look for quantitative crack growth information from the comparison of repeat ultrasonic crack detection ILI runs.
by Luc Huyse and Albert van Roodselaar, Chevron ETC, Houston, TX, USA
With the increased acceptance of the use of probabilistic fitness-for-service methods, considerable effort has been dedicated to estimation of corrosion rate distribution parameters. The corrosion rate is typically computed from the difference in anomaly size over a specific time interval. The anomaly sizes are measured through either in-line inspection or direct assessment. Sizing accuracies for ILI methods are reasonably well established and in many cases the sizing uncertainty is non-negligible. In many approaches proposed in the literature the time-averaged corrosion rates are computed without explicitly considering the effect of sizing uncertainties and, as a result, considerable interpretation and engineering judgment is required when estimating corrosion rates. This paper highlights some of the effects of the sizing uncertainties and the resulting biases that occur in corrosion-rate and, thus, reliability-prediction calculations . These assessments are used to determine the most appropriate course of action: repair, replacement, or time of next inspection. The cost for repair or replacement of subsea pipelines is much higher than for onshore pipelines. For subsea applications, it is therefore paramount that the risk calculations, and therefore the corrosion rate estimates, be as accurate as possible. In subsea applications, the opportunity to repair individual defects is often limited due to practical constraints and there is merit in an approach that focuses on entire spools or pipeline segments. The proposed statistical analysis method is ideally suited to this application although the principles behind the analysis apply equally well to onshore lines subject to either internal or external corrosion threats.
by David Miles, PipeStream, Houston, TX, USA and Phil Tisovec, TD Williamson, Tulsa, OK, USA
A new technology for external rehabilitation of pipelines, known as XHab™, has been developed by Pipestream, Inc. The technology involves wrapping multiple layers of ultra-high strength steel strip (UHSS) in a helical form continuously over an extended length of pipeline using a dedicated forming and wrapping machine. The reinforcement afforded by the strip can be used to bring a defective section of pipe (e.g. externally corroded or dented) back to its original allowable operating conditions, or even to increase the allowable operating pressure if the desired operating conditions exceed the original pipeline design limits. One of the issues with the technique relates to subsequent inspection of the pipeline, specifically:
The paper will discuss an ILI trial performed on a test section of pipe containing an XHab repair. The trial was conducted by T.D. Williamson using a tool with both axial magnetic flux leakage (MFL) and recently-developed spiral (oblique) magnetic flux leakage components. The trial has suggested that:
... FOR DETECTION/SIZING OF SMALL PINHOLE TYPE DEFECTS IN STAINLESS STEEL (DUPLEX) PIPELINES
by Hans Gruitroij, A Hak, Geldermalsen, Netherlands
NAM (part of Shell Exploration and Production Europe) operates several wet gas duplex pipelines in the Netherlands ranging from 4” to 14” in diameter. Given the right conditions these pipelines may suffer from (external) pinhole type of corrosion. As no standard tools are currently available to detect and size these type of defects in this material, it was decided to optimize the ultrasonic Piglet in-line inspection tool from A. Hak Industrial Services for this purpose.
This paper describes the optimization process of the tool, the tests executed to establish specifications and verification, as well as the in-line inspection itself.
The Piglet tool’s principle of operation is based on one ultrasonic transducer mounted centrally and using a rotating mirror which reflects the ultrasonic beam to the surface of the pipe. The mirror can be used to focus the ultrasonic beam, creating a small footprint at the pipe surface or in the pipe wall, thus allowing very small defects to be detected and sized. The rotating mirror principle allows for extreme high resolution, as the number of measurements per circumferential scan can be set without restriction and the tool’s speed can be lowered to enhance the axial resolution.
The pipeline to be inspected was a 12” duplex steel pipeline having wall thickness of 7.6mm and 9.7mm and a length of 12km. The tool was propelled in a batch of water in an otherwise nitrogen-filled pipeline. As only parts of the pipeline were suspected to suffer from this type of corrosion, these areas were inspected with a low inspection speed, hence very high resolution. On other parts the tool speed was increased, hence giving a somewhat lowed axial resolution. All results were monitored online using the tool’s fiber optic link and also stored onboard using the tools on board memory. When all areas of interest were inspected, the tool was reversed and retrieved back into the launcher by the pressurized nitrogen.
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